CONFORMED COPY

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

   Commission File Number  033-63635-04

[] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transaction period from         to            

PDC 1996-D LIMITED PARTNERSHIP

(Exact name of registrant as specified in its charter)

103 East Main Street, Bridgeport, West Virginia 26330

Address of principal executive offices) (zip code)

Registrant's telephone number, including area code (304) 842-3597

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

(Title of class)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.   Yes  X    No     

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as definition in Rule 12b-2 of the Exchange Act). Yes   No X 

There is no trading market for the registrant's securities.

ITEM 1. BUSINESS.

     PDC 1996-D Limited Partnership ("the Partnership") is a limited partnership formed on December 31, 1996 pursuant to the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation ("PDC") serves as Managing General Partner of the Partnership.

     Since the commencement of operations on December 31, 1996, the Partnership has been engaged in onshore, domestic gas exploration exclusively in the Northern Appalachian and Michigan Basins. A total of 9 limited partners contributed initial capital of $324,250; a total of 921 additional general partners contributed initial capital of $14,977,476; and PDC (Managing General Partner) contributed $3,328,126 in capital as a participant in accordance with contribution provisions of the Limited Partnership Agreement (the Agreement). During 1997 in accordance with Partnership Agreement all additional general partners were converted to limited partners.

     Under the terms of the Agreement, the allocation of revenues is as follows:

     Operating and direct costs are allocated and charged to the additional general and limited partners and the Managing General Partner in the same percentages as revenues are allocated. Leasehold, drilling and completion costs, and equipment costs are borne 80% by the additional general and limited partners and 20% by the Managing General Partner. See Footnote 4 of financial statements for a complete description of the allocation of Partnership revenue and costs.

     The Partnership has no employees, however, PDC has approximately 110 employees which include a staff of geologists, petroleum engineers, landmen and accounting personnel who administer all of the partnership's operations.

     The Partnership participated in the drilling of 85 gross wells and will continue to operate and produce its 80 gross productive wells. The Partnership does not have unexpended initial capital and no additional drilling activity is planned.

     See Item 2 herein for information concerning the Partnership's gas wells.

     The availability of a market for any oil and gas produced from the operations of the Partnership will depend upon a number of factors beyond the control of the Partnership which cannot be accurately predicted. These factors include the proximity of the Partnership wells to and the capacity of natural gas pipelines, the availability and price of competitive fuels, fluctuations in seasonal supply and demand, and government regulation of supply and demand created by its pricing and allocation restrictions. Oversupplies of gas can be expected to occur from time to time and may result in the Partnership's wells being shut-in or curtailed. Increased imports of oil and natural gas have occurred and are expected to continue. The effects of such imports could adversely impact the market for domestic oil and natural gas. All oil and gas is sold under contracts based on market sensitive indexes that vary from month to month. No fixed price contracts are in place. Th e Partnership sold oil and natural gas to two customers which accounted for 89.57% and 10.43% of the Partnership's total oil and natural gas sales for the year ended December 31, 2003 and 90.86 % and 9.14% for 2002, respectively.

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     The Managing General Partner, through its subsidiary Riley Natural Gas (RNG), utilizes commodity-based derivative instruments as hedges to manage a portion of the Partnership's exposure to price volatility stemming from its natural gas sales and marketing activities. These instruments consist of NYMEX traded natural gas futures and option contract for Appalachian and Michigan production. The contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within the next twenty-four-month period. The Managing General Partner does not hold natural gas futures or options for speculative purposes and permits utilization of hedges only if there is an underlying physical position.

     The Managing General Partner has extensive experience with the use of financial hedges to reduce the risk and impact of natural gas price changes. These hedges are used to "lock in" fixed prices from time to time for the Partnership's share of production, and to establish "floors" and "ceilings" or "collars" on the possible range of the price realized for the sale of natural gas and oil. In order for contracts to serve as effective hedges, there must be sufficient correlation to the underlying hedged transaction. While hedging can help provide price protection if spot prices drop, hedges can also limit upside potential.

     For unhedged natural gas sales not subject to fixed price contracts, the Partnership is subject to price fluctuations for natural gas sold in the spot market. The Managing General Partner continues to evaluate the potential for reducing these risks by entering into hedge transactions.

     The Partnership competes in marketing its gas with numerous companies and individuals, many of which have financial resources, staffs and facilities substantially greater than those of the Partnership or Petroleum Development Corporation.

     State regulatory authorities have established rules and regulations requiring permits for well operations, reclamation bonds and reports concerning operations. States also have statutes and regulations concerning the spacing of wells, environmental matters and conservation, and have established regulations concerning the unitization and pooling of oil and gas properties and maximum rates of production from oil and gas wells. The Partnership believes it has complied in all material respects with applicable state regulations. The Partnership estimates it has spent approximately $1,050 and $650 in 2003 and 2002, respectively to comply with federal and state regulations.

     Regulation of Liquid Hydrocarbons. Liquid hydrocarbons (including crude oil and natural gas liquids) were subject to federal price and allocation controls until January 1981 when controls were effectively eliminated by executive order of the President. As a result, to the extent the Partnership sells oil produced from its properties, those sales are at unregulated market prices.

     Although it appears unlikely under present circumstances that controls will be reimposed upon liquid hydrocarbons, it is possible Congress may enact such legislation at a future date.

     Natural Gas Regulation. Sale of natural gas by the Partnership is subject to regulation of production, transportation and pricing by governmental regulatory agencies. Generally, the regulatory agency in the state where a producing well is located regulates production activities and, in addition, the transportation of gas sold intrastate. The Federal Energy Regulatory Commission (FERC) regulates the operation and cost of interstate pipeline operators who transport gas. Currently the price of gas to be sold by the Partnership is not regulated by any state or federal agency.

     Proposed Regulation. Numerous proposals concerning energy are being considered by the United States Congress, various state legislatures and regulatory agencies. The possible outcome and effect of these proposals cannot be accurately predicted.

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     Environmental and Safety Regulation. The Partnership believes that it complies, in all material respects, with all legislation and regulations affecting its operations in the drilling and production of oil and gas wells and the discharge of wastes. To date, compliance with such provisions and regulations has not had a material effect upon the Partnership's expenditures for capital equipment, its operations or its competitive position. The cost of such compliance is not anticipated to be material in the future.

ITEM 2. PROPERTIES.

     The following table sets forth the results of drilling activity of the Partnership which was conducted in the Continental United States.

     The Partnership has not participated in any exploratory wells. No additional drilling activity is planned.

See "Management's Discussion and Analysis" on page 5 for Partnership production.

See "Footnote 7" to the Partnership's financial statements for the Partnership's oil and gas reserves.

     During 2002 the Partnership plugged 12 wells in the Angel Unite in Michigan. The table below shows the number of the Partnership's gross and net wells by state as of December 31, 2003.

     A "productive well" is a well producing, or capable of producing, oil and gas in commercial quantities. For purposes of the above table, a "gross well" is one in which the Partnership has a working interest and a "net well" is a gross well multiplied by the Partnership's working interest to which it is entitled under its drilling agreement.

     The Partnership's interests in producing acreage are in the form of assigned direct interests in leases. Such properties are subject to customary royalty interests generally contracted for in connection with the acquisition of properties and could be subject to liens incident to operating agreements, liens for current taxes and other burdens. The Partnership believes that none of these burdens materially interfere with the use of such properties in the operation of the Partnership's business.

     As is customary in the oil and gas industry, little or no investigation of title is made at the time of acquisition of undeveloped properties (other than a preliminary review of local mineral records). Investigations are generally made, including in most cases receiving a title opinion of legal counsel, before commencement of drilling operations. A thorough examination of title has been made with respect to all of the Partnership's producing properties and the Partnership believes that it has generally satisfactory title to such properties.

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ITEM 3. LEGAL PROCEEDINGS.

     The Managing General partner as driller/operator is not party to any legal action what would materially affect the Managing General Partner's or Partnership's operations or financial statements.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

     Not Applicable.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

     At December 31, 2003, PDC 1996-D Limited Partnership had one Managing General Partner, 9 Limited Partners who fully paid for 16.2125 units at $20,000 per unit of limited partnership interests and a total of 921 Additional General Partners who fully paid for 748.8738 units at $20,000 per unit of additional general partnership interests. During 1997 in accordance with the Partnership Agreement all Additional General Partners were converted to Limited Partners. No established public trading market exists for the interests.

     Limited and additional general partnership interests are transferable, however no assignee of an interest in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. There is no established trading market for the securities of the Partnership.

ITEM 6. SELECTED FINANCIAL DATA.

     The selected financial data presented below has been derived from audited financial statements of the Partnership appearing elsewhere herein.

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     The Partnership began exploration and development activities subsequent to the funding of the Partnership and completed these activities by December 31, 1997. Eighty-five wells have been drilled, 80 of which have been completed as producers currently the Partnership has 68 producing wells. No additional wells will be drilled.

     The Partnership had net working capital at December 31, 2003 of $109,808.

     Operations are expected to be conducted with available funds and revenues generated from oil and gas activities. No bank borrowings are anticipated.

     Oil and gas sales for the year ended December 31, 2003 were $1,278,115 compared to $829,395 for the year ended December 31, 2002. The volume of natural gas sold for the year ended December 31, 2003, was 260,912 Mcf at an average sales price of $4.90 per Mcf compared to 279,201 Mcf at an average sales price of $2.97 per Mcf for the year ended December 31, 2002. The lifting costs for the year ended December 31, 2003 was $1.95 per Mcfe compared to $1.82 per Mcfe for the year ended December 31, 2002. This increase is partially attributed to the increase in severance and property taxes. The fixed costs of operations and well maintenance are allocated to lower production volumes, therefore increasing the lifting cost per Mcfe. Cash distributions to the partners amounted to $738,045 in 2003.

     Oil and gas sales for the year ended December 31, 2002 were $829,395 compared to $1,265,406 for the year ended December 31, 2001. The volume of natural gas sold for the ended December 31, 2002 was 279,201 Mcf at an average sales price of $2.97 per Mcf compared to 334,948 Mcf at an average sales price of $3.78 per Mcf for the December 31, 2001. The lifting costs for the year ended December 31, 2002 was $1.82 per Mcfe compared to $1.59 per Mcfe for the year ended December 31, 2001. The net loss of ($194,590) was primarily due to the impairment charge for oil and gas properties which amounted to $519,481 in 2001. This impairment results from net capitalized costs exceeding estimated undiscounted future net cash flows. The impairment was based on estimated fair value which considered future discounted cash flows. Depreciation, depletion and amortization decreased from $390,588 for the year ended December 31, 2001 to $221,614 for the year ended December 31, 2002 a s a result of lower volumes of natural gas and oil sold along with lower net book value of oil and gas properties due to 2001's impairment charge for oil and gas properties. Cash distributions to the partners amounted to $306,591 in 2002.

     The Partnership's revenues from oil and gas will be affected by changes in prices. As a result of changes in federal regulations, gas prices are highly dependent on the balance between supply and demand. The Partnership's gas sales prices are subject to increase and decrease based on various market sensitive indices.

     Certain accounting policies are very important to the portrayal of the Partnership's financial condition and results of operations and require management's most subjective or complex judgments. In applying those policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on our historical experience, our observance of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see "Note 1 - Summary of significant accounting policies" in our financial statements and related notes. The Partnership's critical accounting policies and estimates are as follows:

Revenue Recognition

     Sales of oil and natural gas are recognized when the right and responsibilities of ownership passes to the purchasers and are net of royalties.

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Accounting for Derivatives Contracts at Fair Value

     The Partnership uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing.

     Derivatives are reported on the Balance Sheets at fair value. Changes in fair value of derivatives that are not designated as accounting hedges are recorded in earnings.

    The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Partnership seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Partnership's management.

     For individual contracts, the use of different assumptions could have a material effect on the contract's estimated fair value. In addition, for hedges of forecasted transactions, the Partnership must estimate the expected future cash flows of the forecasted transactions, as well as evaluate the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition in earnings for changes in fair value of certain hedging derivatives.

Oil and Gas Properties

     Exploration and development costs are accounted for by the successful efforts method.

     The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

     In June 2001, the Financial Accounting Standard Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations" that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. The Partnership adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $8,526 and a related liability of $29,649 (using a 6% discount rate) and a cumulative effect of change in accounting principle on prior years of $21,123.

     A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS no. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights (leases) associated with extracting oil and gas intangible assets in the balance sheets, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Partnership has included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Partnership would be required to reclassify the historical cost of approximately $535,823 of mineral rights associated with devel oped oil and gas properties as of December 31, 2003 and 2002 out of oil and gas properties and into a separate intangible mineral rights assets line item. The Partnership's total balance sheet, cash flows and results of operations would not be affected since such intangible assets would continue to be amortized and assessed for impairment.

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Item 7A.  Quantitative and Qualitative Disclosure About Market Risk.

Market-Sensitive Instruments and Risk Management

     The Partnership's primary market risk exposure is commodity price risk. This exposure is discussed in detail below:

Commodity Price Risk

     Natural gas and oil prices have been unusually volatile for the past few years, and the Partnership anticipates continued volatility in the future. Currently, the NYMEX futures reflect a market expectation of gas prices at Henry Hub close to or above record prices per million Btu's (Mmbtu). These prices look strong for 2004 although natural gas storage levels are near normal levels following a period where storage had been at a five-year low. The Partnership believes this situation creates the possibility of both periods of low prices and continued high prices.

     Because of the uncertainty surrounding gas prices the Managing General Partner used hedging agreements to manage some of the impact of fluctuations in prices for the Managing General Partner and its various limited partnership's share of the production. Through October of 2004 the Partnership has in place a series of costless collars and option contracts. Under the collar arrangements, if the applicable index rises above the ceiling price, the Partnership pays the counterparty, however if the index drops below the floor the counterparty pays the Partnership. For the period from January 2004 through March 2004, the Partnership has floors in place in a range from $4.20 to $4.45 on 7,585 Mmbtu of monthly production and ceilings in place in a range from $5.00 to $5.40 on 3,793 Mmbtu of monthly production. For the period April 2004 through October 2004, the Partnership has floors in place in at $4.00 on 5,418 Mmbtu of monthly production and ceilings in place at $5. 65 on 5,418 Mmbtu of monthly production. As of December 31, 2003 the Partnership had option contracts for the sale of 49,304 Mmbtu of natural gas with an average ceiling price of $5.55 and for the sale of 60,682 Mmbtu of natural gas with an average floor price of $4.12. The fair value of open contracts as of December 31, 2003 is ($8,800).

The average NYMEX closing price for natural gas for the years 2003, 2002 and 2001 was $5.39 per Mmbtu, $3.22 per Mmbtu, and $4.27 per Mmbtu with a range from $1.83 per Mmbtu to $9.98 per Mmbtu. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulations and new drilling activities within the industry

Disclosure of Limitations

     As the information above incorporates only those exposures that exist at December 31, 2003, it does not consider those exposures or positions which could arise after that date. As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations will depend on the exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.

     The response to this Item is set forth herein in a separate section of this Report, beginning on Page F-1.

        FINANCIAL DISCLOSURE.

      NONE.

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     Under the supervision and with the participation of the Managing General Partner's management, including the Managing General Partner's Chief Executive Officer and Chief Financial Officer, the Managing General Partner has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) as of the end of the period covered by this annual report on Form 10-K, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Commission's rules and forms, and is accumulated and communicated to management, including the Managing General Partner's Chie f Executive Officer and Chief Financial Officer, as appropriate to allow for timely disclosure. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls in the fourth quarter and subsequent to the date of their evaluation.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY.

     The Partnership has no directors or executive officers. The Partnership is managed by Petroleum Development Corporation (the Managing General Partner). Petroleum Development Corporation's common stock is traded in the NASDAQ National Market and Form 10-K for 2003 has been filed with the Securities and Exchange Commission.

      NON-APPLICABLE.

      NON-APPLICABLE.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     Pursuant to the authorization contained in the Limited Partnership Agreement, PDC receives fees for services rendered and reimbursement of certain expenses from the Partnership. See respective drilling prospectus for further information regarding the Limited Partnership Agreement. The following table presents compensation or reimbursements by the Partnership to PDC or other related parties during the years listed below:

     For the years ended December 31, 2003, 2002 and 2001, KPMG LLP provided auditing services in the amount of $8,133, $7,673 and $7,378, respectively.

     The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent accountants be subject to pre-approval by the Audit Committee or authorized members of the Committee. Since the Partnership does not have an Audit Committee, the Managing General Partner's Audit Committee also serves for the Partnership. The Audit Committee has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Partnership's independent accountants. Services necessary to conduct the annual audit must be pre-approved by the Audit Committee or by the authorized Audit Committee member.

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 10-K.

(a) (1) Financial Statements

See Index to Financial Statements on F-2

(2) Financial Statement Schedules

(b) Reports on Form 8-K during the fourth quarter.

None.

1. Exhibits

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CONFORMED COPY

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Statements for Annual Report

on Form 10-K to Securities and Exchange

Commission

Years Ended December 31, 2003, 2002 and 2001

(With Independent Auditors' Report Thereon)

F-1

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

All financial statement schedules have been omitted because they are not applicable or not required or the required information is shown in the financial statements or notes thereto.

F-2

To the Partners

PDC 1996-D Limited Partnership:

We have audited the financial statements of PDC 1996-D Limited Partnership (a West Virginia limited partnership) as listed in the accompanying index. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PDC 1996-D Limited Partnership as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 1 to the financial statements, the Partnership adopted the provisions of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations", in 2003. Also, as discussed in note 1 to the financial statements, the Partnership changed its method of accounting for derivative instruments and hedging activities in 2001.

KPMG LLP

Pittsburgh, Pennsylvania

March 15, 2004

F-3

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Balance Sheets

December 31, 2003 and 2002

See accompanying notes to financial statements.

F-4

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Operations

Years Ended December 31, 2003, 2002 and 2001

See accompanying notes to financial statements.

F-5

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Partners' Equity

Years Ended December 31, 2003, 2002 and 2001

See accompanying notes to financial statements.

F-6

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Cash Flows

Years Ended December 31, 2003, 2002 and 2001

See accompanying notes to financial statements.

F-7

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

Years Ended December 31, 2003, 2002 and 2001

(1)    Summary of Significant Accounting Policies

(2)    Organization

(3)    Transactions with Managing General Partner and Affiliates

(4)    Allocation

F-11

(5)    Costs Relating to Oil and Gas Activities

F-12

(6)    Income Taxes

(7)    Supplemental Reserve Information (Unaudited)

and Gas Reserves (Unaudited)